The reliable, safe and economic production of hydrocarbons is critical to the oil and gas industry. In many instances, hydrocarbon reserves trapped within certain low permeability formations, such as certain sandstone, carbonate, and/or shale formations, exhibit little or no production, and may therefore be undesirable to develop. Methods such as well stimulation may increase the permeability and hence the production of an otherwise unproductive formation or reservoir.
During well stimulation operations, chemicals can be injected into the formation in a process known as well stimulation. Exemplary stimulation techniques include: (1) the injection of chemicals capable of dissolving portions of the formation and creating alternative flow paths for recoverable hydrocarbons through, for example, acid- or matrix-fracturing processes; and (2) the injection of water and/or non-aqueous chemicals through the wellbore and into the formation at pressures that are sufficient to fracture the formation, thereby creating new or additional flow channels through which hydrocarbons can more readily move from the formation into the wellbore.
In certain tight reservoirs, well productivity is typically low, thus making the well non-economical from a standpoint of development. One commonly employed technique for stimulating low productivity wells is hydraulic fracturing, which can involve the injection of fluids, such as high viscosity fluids, into the well at a sufficiently high rate so that enough pressure is built up inside the wellbore to split the formation apart or form fractures. The resulting hydraulically induced fracture can extend from the wellbore deep into the formation.
Hydraulic fracturing fluids are used extensively to enhance productivity from hydrocarbon reservoir formations. These fluids may be supplemented with proppants or other compositions for inducing or increasing fracture conductivity (hereinafter “conductivity”), defined as the product of fracture permeability times the fracture width for a finite conductivity fracture, in a reservoir. In the quest to produce more natural gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nanodarcy to microdarcy range. The main challenges associated with working in such formations are the intrinsically high temperature and high pressure bottom hole conditions. For formations with bottom hole temperatures around 350-450° F., traditional hydraulic fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be employed at high concentrations in order to suspend proppants. The high polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can lower or even block formation conductivity to gas flow.